Southwestern Energy : 2Q 2017 Teleconference Transcript

Participants

Michael Hancock - Vice President of Investor Relations Bill Way - President & Chief Executive Officer

Jennifer Stewart - Chief Financial Officer

Jason Kurtz - VP of Marketing and Transportation Jack Bergeron - SVP of Operations

Paul Geiger - SVP of Corporate Development.

Analysts

Scott Hanold - RBC

Charles Meade - Johnson Rice

Dan McSpirit - BMO Capital Markets Karl Chalabala - Stifel

Brian Singer - Goldman Sachs Doug Leggate - Bank of America Holly Stewart - Scotia Howard Weil Bob Morris - Citi

Jason Gilbert - Goldman Sachs Sean Sneeden - Guggenheim Dave Tameron - Wells Fargo

Presentation

Greetings, and welcome to Southwestern Energy Company Second Quarter 2017 Earnings Teleconference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. In the interest of time, please limit yourself to two questions. Afterwards, you may feel free to re- queue for additional questions. [Operator instructions]. As a reminder, this conference is being recorded.

It is now my pleasure to introduce Michael Hancock, Vice President of Investor Relations for Southwestern Energy Company.

Thank you, Rob. Good morning and thank you for joining us today. With me today, are Bill Way, our President and Chief Executive Officer; Jennifer Stewart, our Chief Financial Officer; Jason Kurtz, our Vice President of Marketing and Transportation; Jack Bergeron, our Senior Vice President of Operations; and Paul Geiger, Senior Vice President of Corporate Development. If you've not received a copy of last night's press release regarding our second quarter 2017 financial and operating results, you can find a copy on our website at swn.com.

Also, I'd like to point out that many of the comments during this teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes. Many of these are beyond our control and are discussed in more detail in the risk factors and the forward-looking statements section of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially.

We may also refer to some non-GAAP financial measures, which help facilitate comparisons across periods and with peers. For any non-GAAP measures we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release available on our website.

I'll now turn the call over to Bill Way to discuss our results and recent activity.

Thanks, Michael. Good morning everyone and thanks for joining us on our call today. We really are delighted to have you on the call to discuss the latest achievements here at Southwestern and some of the strong differentiating results that our very highly talented teams across the country have delivered throughout the portfolio.

As you saw in last night's release, we once again delivered the solid results that we guided back in February. We did this, as we promised, while investing within cash flow and for our fully funded capital plan. We continue to monitor commodity prices and remain committed to adjusting our capital program to align with price changes as we move into the second half of 2017 and beyond.

As we continue to demonstrate, we believe that focusing on the highest return projects and investing within cash flow results in differentiating shareholder value. Production growth is an outcome of our plans, not a driver for them. As we look forward, we believe that the increasing demand and the lower than anticipated supply response that we're currently seeing has been evidenced by the recent trend of strong weekly gas storage reports has yet to be reflected in the forward curve.

The billions of dollars being invested in new gas driven power plants and industrial facilities, coupled with continuing opportunities of increased exports to Mexico and from LNG, are expected to increase demand by over 10 billion cubic feet per day over the next four years.

With the decline of many basins outside of Appalachia, additional drilling will need to be incentivized to meet this growing demand. One source of this needed supply is expected to be associated gas from the Permian.

However, in this current oil price environment, and with takeaway solutions from the region being required but being fully subscribed, we think the supply will need to be supplemented by other regions of dry gas.

In addition to the encouraging outlook for natural gas prices, the basis differential outlook also continues to improve due to the momentum on pipeline infrastructure in the Northeast United States. As you know, we now have a quorum at the FERC and this quorum should facilitate the approval of certificates to initiate construction on approximately 10 Bcf per day of new takeaway capacity in addition to the 5 Bcf per day of capacity that is currently under construction, increasing the total takeaway from the Northeast region by approximately 15 billion cubic feet per day between now and 2020.

Rover, alone, which is getting a lot of attention right now in the press due to its impending end service date, we will deliver capacity of over 3 billion cubic feet a day once it gets full. While there are many delays talked about in the press around Phase 1 of this project, we want to remind everyone that our 200 million a day of firm capacity is on Phase 2 which is still expected to be online near the end of 2017, as we have modeled. We do not anticipate any impacts to our development schedule should there be a delay in Phase 2 as we proactively identified alternative operations for additional capacity on a short-term basis, if we need it.

Focusing on our Northeast Appalachia asset for a moment, during this quarter, we added approximately 140 million cubic feet per day of new firm takeaway capacity at an average cost of only a $0.10 per Mcf, substantially lower than our already impressive low cost transportation portfolio out of the area. This new capacity, which facilitates further growth, will deliver volumes to be priced off of the Dominion Appalachia Index, which is expected to improve even further from historic levels as additional Southwest Appalachia pipelines come online.

Let me switch now to the quality performance of our portfolio. The company had a total net production of 222 Bcf equivalents in the second quarter, a 9% increase compared to the first quarter of 2017 despite third-party gathering issues. The company's operations were impacted in the second quarter by a one-off delay in the

installation of a small third-party field gathering line in Susquehanna County that was expected to come on in early 2017 and the third-party compressor station that unexpectedly went off line for repair in late June.

We are leveraging our differentiating midstream gathering expertise, our commercial optimization capabilities and our flexible gathering systems across the state and working closely with our third-party gatherer to diligently implement measures mitigating this operational downtime. As I've said before, these are one-off events, are not structural changes and do not change our development plans.

Now, let me turn over to Jennifer to discuss some of our financial highlights.

Thanks, Bill, and good morning, everyone. I'm excited to be here today and for those of you that I haven't had a chance to meet, I look forward to meeting you on the road soon.

Strengthening the balance sheet remains a key focus for the company, and to that end in the second quarter of 2017, we retired our remaining 2018 senior notes and will retire the 40 million in 2017 senior notes upon the maturity in the fourth quarter. While we have no other near-term maturities, we will continue to look for ways to opportunistically de-lever or extend our maturities in order to further strengthen our liquidity and credit profiles.

As Bill mentioned, financial discipline drives our decision-making process and our robust hedging program provides protection of cash flows and ensures targeted returns. We made additional progress on building our hedge book during the second quarter, as we now have over 400 Bcf of 2018 production hedged at an average swap of a purchased put strike price of approximately $3 per Mcf with upside exposure on approximately 72% of those protected volumes up to $3.39 per Mcf. The company also has over 100 Bcf hedged for 2019 at an average purchased put strike price of $2.95 with upside exposure up to $3.32 per Mcf.

Our 2018 and 2019 positions continue to be predominantly collars in order to retain upside exposure to expected improvements in commodity prices. We continue to see the benefits of an improving commodity price environment this quarter. Compared to the second quarter of 2016, realized natural gas prices, excluding hedges, increased 94% to $2.35 per Mcf. Improvement also continues to be seen with NGL pricing. Our realized C3 plus NGL prices were $21.62 per barrel including transportation costs, up 46% from $14.78 per barrel in the second quarter of 2016. Our total NGL barrel realization, inclusive of transportation charges, was $11.25 per barrel, up 76% compared to $6.41 per barrel in the second quarter of 2016.

I will now turn it over to Jack for an operational update.

Thanks, Jenifer, and good morning, everyone. In the second quarter, we invested approximately $318 million in our E&P business and had total net production of 222 Bcf, an increase of approximately 9% compared to the first quarter of the year. This includes an increase in our Appalachian Basin of 140 Bcf or 14%. We're continuing to progress our technical learnings and apply these learnings across our portfolio. We have been achieving our leading operating capability related to extended laterals, lateral placement, completion intensity and optimized flow techniques. These achievements represent a step change in how the company is approaching well design to maximize value and again confirm Southwestern as a leader in US shale gas development.

For example, in Northeast Appalachia, the company has increased the average lateral length of its wells by over 10% since 2015, while staying in the targeted interval over 90% of the time, a substantial improvement from the approximately 75% precision back in 2015. Two of these wells were recently completed with average lateral lengths of over 11,000 feet. The most recent example of this is the Seymour 1H, which is demonstrating productivity among the top 10% of the company's wells ever drilled in Bradford County on a CLAT-adjusted basis. This well with a lateral length of over 12,000 feet delivered an initial production rate of 37.7 MMcfe per day.

The company is also seeing continued success with its increased completion intensity testing across its acreage. In Southwest Appalachia, the Ritchea pad in Wetzel County continues to outperform its offsets by approximately 25% after the first 160 days of production. Two of the wells on this pad were completed with 3,500 pounds of profit per foot with 140 foot stage facing. Additionally, in Marshall County, we placed the Michael Dunn pad online

in the second quarter of 2017. After over three months of production, this four well pad is at a flat pad rate of 38 MMcfe per day, 44% of which is liquids, at an average flowing casing pressure of 2,400 psi. Early indications suggest the new completion designs are outperforming the old standard completion design by 25%.

The continuous improvements made in our core acreage positions were also delivering benefits in our delineation testing throughout our portfolio that could unlock additional value. In Southwest Appalachia, our first company drill of Utica well continues to perform as a top quartile well with cumulative production of over 2 Bcf in its first six flowing months. The well is currently flowing at a flat rate of 15 MMcfe of gas per day with a casing pressure of approximately 6,000 psi. And based on our extensive analysis, it's projected to remain flowing at this rate until sometime in 2018. We have recently finished drilling and completing our second Utica well in Washington County, and are in the process of completing the final steps of bringing this well online and expect to have results later this year.

In the Fayetteville, we progressed our learnings with the Moorefield where we brought two additional wells online this quarter, one of which encountered a fall which has resulted in increased water production and limited early stage productivity. The second well confirmed our geologic understanding and was brought online with a 5 MMcfe per day, 30th day rate, and an initial EUR of over 5 Bcf. We expect to bring additional delineation wells online throughout the remainder of 2017.

This concludes our prepared remarks. We'll turn it back to Rob, who will explain the procedure for asking questions.

Thank you. We will now be conducting a question-and-answer session. [Operator instructions]. Our first question comes from the line of Scott Hanold with RBC. Please go ahead with your question.

Q: Bill, you talked a little bit about, and you wrote on it in your release, some of the actions you took to mitigate some of the downtime in the Northeast. Could you give a little bit more color on exactly what you're doing? As we think of that, is this something that you feel comfortable that it's going to be available to you going forward? What's the cost of these options?

Yes, let me start with the slow pipeline jumper that we talked about. If you imagine going out into the extents of the gathering systems and looking at hydraulic opportunities for linking them together, so we're not anywhere near a major trunk line, these are out in the gathering system. There was a delay of getting a permit. So the pipeline will get put on, it's only a mile long or two miles long. It's not even a major trunk line. That will get sorted, be done.

Our gathering system has a number of tie-in points, if you look at that one alone. But if you look at our company, we've got gathering systems and capabilities all over the state. So we can optimize and move things around, so that one-off gathering issue is there, it'll be finished, there's not anything holding that up.

The compressor station issue had to do with some vibration issues at the station. Station has been nearly completely rebuilt. They are working on the final pieces of equipment that have to do with pulsation and dampening. They'll get that done. The machines are set, the roof's being put on, and I mean it's getting done. So we also have flexible delivery from our network of marketing opportunities and firm transportation that enables us to move volume around which enables us to, again, mitigate any issues with from the gathering site going to that compressor station.

So, again a one-off issue unfortunate for the company, the compressor company, but we moved it around. The cost to mitigate all of this is really not a cost to mitigate, it's shifting deliveries from one pipeline network to another to deal with the compressor issue and moving around and seeing what further optimization we can have on our gathering system. I think in the gathering system, and it's actually a sort of a wake-up to you that says are there further ways we can optimize this gathering system and optimize gas flows for the future, as we get past all of this.